This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate the understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
In processing fluids, the measurement of fluid flow through a passage provides information that may be utilized to manage the fluid in a more effective manner. In particular, the measurement of flow components for a multi-phase fluid may be utilized to provide information, which may be used to indicate or troubleshoot a problem and/or adjust settings to enhance operations. These flow measurement devices may be utilized in enclosed passages, such as conduits, wellbores, or other defined fluid flow paths. In particular, measurement of flow components in production logging can provide information about the properties of the produced well fluid. This information may be utilized to identify potential problems (e.g., water intrusion and/or cross contamination) and/or determine the fluids being produced from various zones within the reservoir. As a result, equipment settings may be adjusted and/or maintenance may be performed to enhance fluid production, such as petroleum production.
To provide flow measurements, various devices may be utilized within the flow passage to collect flow measurement information. One such device is a heat-pulse flow meter (HPFM), which heats a volume of fluid within the passage. This flow meter has one or more sensors disposed within the flow meter to measure the temperature for given periods of time. The changes in temperature indicate that the heated fluid is flowing within the passage, which is utilized to determine a rate of flow and direction of flow at that particular location and time. However, the operation for this type of device may be limited because it is stationary during the measurements and it has a limited range of flow rates it can measure. Further, as it involves heating a volume of fluid, it is not useful for environments where higher temperatures and/or higher flow rates are present. Moreover, the obtained measurement for this device is dependent on the calibration (which is dependent on the heat capacity coefficient of the measured fluid) and fluid properties of a mixture of different fluids with unknown volume fractions (such as the case for multi-phase flows) cannot be determined.
Another flow measurement device is an electromagnetic flow meter (EMFM). This flow meter generates a magnetic field to measure the fluid flow through the flow meter. The generated voltage is utilized to determine the rate of flow and direction of flow at that particular location and time. However, this measurement device is based on the conductive properties of water and is not useful for tracking the flow of hydrocarbons. Additionally, this type of device is limited in the range of flow rates it can measure based on its configuration.
Yet another type of flow measurement device is a spinner or impeller flow meter. The spinner flow meter typically has an impeller or propeller assembly with a symmetric distribution of two or more blades that revolve around a shaft in response to fluid flow. A sensor may be utilized to determine the revolution speed, which is used to determine the rate of flow and direction of flow at that particular location and time. These measurements may be made while moving the flow meter through an enclosed passage or at a stationary position within the enclosed passage. The spinner flow meter provides a wider range of flow rates, but typically has limited accuracy for low flow rates (e.g., less than 5 feet per minute).
Each of these flow meters may be utilized in different environments to provide information about fluid flow. For example, flow measurements from flow meter log data may be obtained and analyzed in hydrocarbon production to provide qualitative and quantitative reservoir characteristics. The temperatures in the wellbores may include temperatures in the range of 0° C. to 630° C., or −17° C. to 350° C. and the pressures within these zones may include 0 to 1000 atmospheres gauge (0 kilo Pascal gauge to 100 mega Pascal gauge). Differences in pressure produce fluid flow into the wellbore and within the wellbore toward the surface. The flow measurements may be utilized for the hydraulic analysis of zones, the enhancement of reservoir models, or the design and implementation of well completions.
While the spinner flow meter is more suitable for certain environments, such as hydrocarbon production operations, the conventional spinner flow meters fail to properly measure the flow when multiple phases are present. As an example, a typical production logging tool string includes various components, including one or more flow meters. A typical spinner flow meter consists of a multi blade impeller, which is disposed at the center of a housing (e.g., a tubing member) by stabilizers. The housing protects the impeller from contact with the walls of the enclosed passage, may maintain the impeller within the center of the enclosed passage, and may provide paths for fluids to contact the blades of the impeller assembly. As the velocity of the fluid flow varies over the cross area of the enclosed passage (e.g., being about zero at the wall to a maximum at the center), the multi-blade impeller should be maintained in the center of the housing to provide accurate measurement of flow. The rotation speed of the blades can be correlated to the average fluid flow speed through the enclosed passage.
While this configuration measures the fluid flow rate properly for single-phase flow, the fluid flow regime in hydrocarbon production systems, such as within a wellbore, often consists of multiple phases, such as a mixture of oil, gas and/or water. As such, the composition of fluid being produced (i.e., production fluid) is a result of a wellbore crossing multiple production zones, where different components (e.g., oil, gas, or water) enter the wellbore and contribute to the production fluid flow. As an example, dissolved gas eventually separates as the pressure decreases (e.g., gas is dissolved at greater depths within the wellbore that are subject to higher pressures compared to shallower depths). Accordingly, the composition of production fluid and flow regime may change at different locations, as the volume fraction of the different components (oil, gas and/or water) varies along the wellbore. Depending on the relative volumetric fraction of the liquid phase and gas phase, the flow regime can include a wide spectrum of flows. For substantially horizontal portions of a wellbore, the flow regimes may include a dispersed bubble flow (e.g., evenly distributed gas bubbles are suspended in a predominantly liquid flow), plug flow (e.g., elongated bubbles), slug flow, stratified smooth flow or stratified wavy flow (e.g., liquid and gas flow in two distinct layers) or annular flow. See, e.g., J. M. Mandhane, C. A. Gregory and K. Aziz, “A Flow Pattern Map for Gas-Liquid Flow in Horizontal Pipes,” Int. J. Multiphase Flow, 1(4), pp 537-554, 1974. The occurrence of specific multi-phase flow regimes also depends on other factors, such as conduit or tubing orientation and size, overall production rate, pressure, and temperature. Consequently, different flow regimes may be present at different locations along the same well at the same time.
Further, the multiple phases may also pass through the wellbore at different velocities. As an example in a horizontal wellbore, the gas phase of a stratified flow is located in the upper region of wellbore and has a velocity that may be higher compared to the liquid phase flowing in the bottom portion of the wellbore. For slug flow, the liquid phase and gas phase are separated and form an intermittent sequence of different phases. The phases produce a time-dependent behavior of the local velocity whereby the liquid phase may recirculate as the gas phase (e.g., bubbles) passes through the wellbore. Thus, the flow regime is determined from the velocity variation at a given location, which depends on the boundary conditions and the different densities and viscosities of the fluid.
The flow regime complicates the measurement of the flow regime with conventional spinner flow meters, as they do not properly account for multi-phase flows. That is, conventional spinner flow meters fail to provide accurate measurements because the correlation between rotation speed and actual flow speed is based on fluid properties (e.g., density and viscosity) for specific single-phase flows. Indeed, the use of such flow meters requires a previous knowledge of the fluid to be measured (e.g., composition of water, oil, and/or gas) and the inadequacy of a conventional spinner flow meter for multi-phase flows is evident as the definition itself of local flow velocity blurs. Consequently, the accuracy of measurement quickly decays in regions where multi-phase flow is encountered by the flow meter. Although production logging spinner flow meters are used to log both single-phase and multi-phase flows in producing wells, the identification of the regions with multi-phase flow is challenging. The spinner flow meter responses to multiple phase flow are difficult to interpret, and often lead the operator to discard log data from regions where multi-phase flow is suspected. Moreover, signal filtering processes are commonly built in the monitoring system to hide such inaccuracy, which may result in incorrect interpretations of the well dynamics.
As the operation and surveillance of production systems rely, in part, on the accurate measurement of the contribution of each of the phases in the flow regime to the overall production flow, a need exists to enhance the information collected in systems that have multi-phase flow. Further, an enhanced system, which may be utilized to determine cross flows present between zones and/or water entering the wellbore from one or more zones, may also be beneficial.